The present invention relates to an oil recovery process for a subterranean heavy oil-containing reservoir. More particularly, the invention relates to an improvement in an in situ oil recovery process wherein steam is injected to heat the reservoir and thus render the heavy oil more mobile for recovery.
Heavy oil-containing reservoirs are those which contain crude petroleum or bitumen of such high viscosity that it cannot be recovered by conventional petroleum recovery techniques. Exemplary of such formations are the Athabasca oil sand deposits, the Lloydminster heavy oil deposits present in Alberta, Canada, the Kern River deposit in California, U.S.A., and the Orinoco River deposit in Venezuela. An in situ process for the recovery of such heavy oil and bitumen has a goal to reduce the viscosity of the heavy oil or bitumen and thereby make it more amenable to flow.
Steam has long been used in the recovery of oil from these heavy oil-containing reservoirs. In situ oil recovery processes using steam are hereinafter referred to as "steamflooding" processes.
In some cases, a communication zone, that is a permeable pathway, is first established between at least two wells penetrating the heavy oil-containing stratum. A communication zone may exist as naturally occurring permeable strata or may be established by conventional methods of hydraulic fracturing and propping. The steam is then injected through one well at high temperature and pressure. The steam passes through the communication zone, transferring sufficient heat to the heavy oil to lower the viscosity of same and render it more mobile. A steam/steam condensate/heavy oil mixture is produced at the second well.
Alternatively, steam injection and oil production may both take place through a single well penetrating the reservoir. Steam is injected through the well into the formation. The steam is injected at high temperature and pressure to create a steam zone or steam chest exterior the well. When the injection pressure reaches a pre-determined level, injection is stopped and a back flow of heated formation fluids and injected fluids flows into the well and is produced. The injection and production cycles are repeated.
In situ recovery methods using steam injection, whether by continuous steam drive, steam soak or cyclic steam techniques, have the disadvantage of leaving behind substantial amounts of oil. To enhance these steamflooding processes, steam additives, such as solvents and gases, are used. The solvent is included to solubilize some of the heavy oil and thereby lower the oil viscosity. Gaseous additives, such as carbon dioxide, are believed to enhance oil recovery by coming out of solution during pressure drawdown and assisting in the pressure drive during the production cycle.
People have considered injecting surfactant with steam; however, in general, surfactants are not thought to be stable at the high temperatures needed for steam injection. For this reason, most of the prior art to date has either taught one to inject only low temperature (&lt;180.degree. C.) steam when using surfactants, or to inject the surfactant in slugs separate from the steam to protect the surfactant from the steam temperatures.
The majority of the heavy oil-containing reservoirs, because of their depth and high oil viscosity, cannot be feasibly recovered at temperatures of less than about 180.degree. C. which, for saturated steam, corresponds to about 150 psi (1 MPa).
A number of thermal stability studies on surfactants have been recently reported by researchers looking for a surfactant sufficiently stable at steam temperatures to warrant its inclusion in a steamflooding process. These studies include Gopalakrishnan, P., et al., "Injection of Steam With Surfactant Solution", SPE 7109, (1978); Handy, L. L., et al., "Thermal Stability of Surfactants for Reservoir Application", SPE 7869, (January, 1979); and Owete, O. S., et al., "Screening of Foaming Agents for Use in Steam Injection Processes", 1980 Annual Heavy Oil/EOR Contractors Presentations--Proceedings, U.S. Department of Energy, (September, 1980).
These researchers have tested, among other surfactants, organic sulfonate surfactants, which are known to possess relatively stable carbon-sulfonate linkages.
The studies concluded that the kinetics of the thermal decomposition of a surfactant such as a petroleum sulfonate surfactant, is first order with a half life at 177.degree. C. of about 11 days. The studies state this to be insufficient thermal stability for use in steamflooding processes, at least for steam temperatures greater than about 180.degree. C.
Another factor which has discouraged the use of surfactants with steam is that several studies have assumed or predicted that surfactants, in a steamflooding process, preferentially travel with the water (steam condensate), rather than with the steam, in the reservoir, see for example Ziegler, V. M., et al., "Effect of Temperature on Surfactant Adsorption in Porous Media", SPE 8264, (September, 1979). Thus one would not expect to see the benefits of the surfactant in the steam zone of the reservoir. This naturally detracts from the value of including a surfactant in a steam-flooding oil recovery process.